Natural gas is the most important fuel gas in the United States and provides more than one-fifth of all the primary energy used in the United States. Natural gas is also used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. For example, a raw gas stream may contain as much as 95% methane, with only minor amounts of other hydrocarbons, nitrogen, carbon dioxide, hydrogen sulfide or water vapor. On the other hand, streams with large proportions of one or more of these contaminants are common. For example, gas that is extracted as a result of miscible flood enhanced oil recovery may be very rich in carbon dioxide, as well as being saturated with C3+ hydrocarbons.
Overall, about 10% of gas exceeds the typical gas pipeline specification for carbon dioxide of no more than 2%. About the same percentage of gas is out of specification because of excess nitrogen.
Before such gas can be sent to the supply pipeline, the carbon dioxide content, nitrogen content or both must be reduced. Various techniques for acid gas removal, including absorption into an amine solution, cryogenic separation and membrane separation, have been used in the industry. For nitrogen removal, cryogenic separation has been used, and membrane separation is beginning to be introduced.
Membrane separation is attractive, because membrane systems are simple compared with amine or cryogenic technology. They have few moving parts, can operate under moderate temperature and pressure conditions, do not require a regeneration cycle, can be mounted on mobile skids, and are cost-effective for small production capacities.
Many patents describe the use of membrane separation to remove carbon dioxide from gas streams. U.S. Pat. No. 4,130,403 describes a method for removing hydrogen sulfide or carbon dioxide from natural gas using cellulose acetate membranes. These membranes remain in commercial use today.
U.S. Pat. No. 4,435,191 describes the use of multiple membrane units in series to remove carbon dioxide from a gas mixture. The residue from one unit is passed to the next stage for treatment. Compression steps raising the gas to progressively higher pressures are carried out between each stage.
U.S. Pat. No. 6,128,919 describes attempts to limit the power requirements of multistage membrane systems by operating at low power, and keeping the pressure to which gas streams are compressed below about 100 psig.
U.S. Pat. No. 6,648,944 describes a process for removing C3+ hydrocarbons and carbon dioxide from natural gas, using a first membrane stage to remove the hydrocarbons and second and third stages to remove the carbon dioxide.
U.S. Pat. No. 6,565,626 describes processes for removing nitrogen from natural gas using nitrogen-selective membranes. Two-stage and three-stage process designs are shown.
U.S. Pat. Nos. 6,572,678 and 6,572,679 describe processes for removing nitrogen or carbon dioxide from gas mixtures using combinations of membranes that selectively permeate and selectively reject carbon dioxide and nitrogen compared with methane. Two-stage process designs are shown.
Despite the many advances that these patents represent, it is still difficult under field conditions to meet desired composition and recovery specifications. One problem is that carbon dioxide readily sorbs into and interacts strongly with many polymers, swelling or plasticizing the membrane, and thereby adversely changing the membrane permeation characteristics. Thus, even materials with high ideal selectivity for carbon dioxide over methane can provide a selectivity of only about 9 or 10 under real mixed gas, high-pressure conditions.
Such membranes can reduce the carbon dioxide content of the treated, residue gas stream to a target value of, for example, 2%, but, because the selectivity is modest, unacceptable quantities of methane will permeate with the carbon dioxide, and will be lost in the permeate stream.
Separation of nitrogen from methane by means of membranes also remains of limited utility because of very low selectivities. Whether methane-selective or nitrogen-selective membranes are used, selectivity is typically only about 2 or 3. As with carbon dioxide separation, unacceptable losses of methane into the permeate stream occur.
To overcome the low selectivity problems, multistage systems have been proposed in the literature, as shown in the patents cited above, and are in use to a limited extent. In an example of such a system, the permeate from the first membrane separation stage is passed as feed to a second stage, and the methane-rich residue is recycled to the first stage to reduce methane loss. To maintain adequate driving force for transmembrane permeation in the second stage, and to facilitate residue recycle, the first-stage permeate must be recompressed, usually to the pressure of the raw feed gas.
The need for interstage compression greatly increases the capital cost of the membrane system. The introduction of the compression step also affects the operating costs, as the power requirements and maintenance costs are likely to be higher.
Further, the addition of a second membrane stage may not raise the methane recovery to the point that treatment of the raw gas becomes worthwhile.
For these reasons, much potentially valuable natural gas remains in the ground unexploited, awaiting better treatment technology.